1. Field of the Invention
The present invention relates to methods and compositions for treating subterranean well formations, and more specifically, to improved subterranean formation treating fluid concentrates, treating fluids and methods of using such treating fluids in subterranean formations.
2. Description of Related Art
Producing subterranean formations penetrated by well bores are often treated to increase the permeabilities or conductivities thereof. One such production stimulation treatment involves fracturing the formation utilizing a viscous treating fluid. That is, the subterranean formation or producing zone therein is hydraulically fractured whereby one or more cracks or “fractures” are produced therein. Fracturing may be carried out in wells that are completed in subterranean formations for virtually any purpose. The usual candidates for fracturing or other stimulation procedures are production wells completed in oil and/or gas containing formations. However, injection wells used in secondary or tertiary recovery operations for the injection of fluids may also be fractured in order to facilitate the injection of fluids.
Hydraulic fracturing may be accomplished by injecting a viscous fracturing fluid into a subterranean formation or zone at a rate and pressure sufficient to enhance or create one or more fractures in a desired location within the formation. As the fracture is created a portion of the fluid contained in the viscous fracturing fluid leaks off into the permeable formation and a filter cake comprised of deposited gelling agent may be built up upon the walls of the fracture which then helps to prevent or reduce further fluid loss from the fracturing fluid to the formation. The continued pumping of the viscous fracturing fluid extends the fractures. Proppant such as sand or other particulate material may be suspended in the fracturing fluid and introduced into the created fractures. The proppant material functions to prevent the formed fractures from closing upon reduction of the hydraulic pressure, which was applied to create the fracture in the formation or zone whereby conductive channels remain through which produced fluids can readily flow to the well bore upon completion of the fracturing treatment.
The fracturing fluid should have a sufficiently high viscosity to retain the proppant material in suspension as the fracturing fluid flows into the created fractures. A viscosifier has heretofore often been utilized to increase the viscosity of a base fluid. After the viscosified fracturing fluid has been pumped into the formation and fracturing of the formation has occurred, the fracturing fluid generally has been caused to revert into a low viscosity fluid for removal from the formation by breaking the gel. The breaking of viscosified fracturing fluids has commonly been accomplished by utilizing a breaker with the fracturing fluid.
The fracturing fluids utilized heretofore have predominantly been water-based liquids containing a gelling agent comprised of a polysaccharide such as guar gum. Guar and derivatized guar polymers such as hydroxypropylguar are water soluble polymers that may be used to create high viscosity in an aqueous fluid and may be readily crosslinked to further increases the viscosity of the fluid. While the use of gelled and crosslinked polysaccharide fracturing fluids has been highly successful, such fracturing fluids have not been thermally stable at temperatures above about 200° F. That is, the highly viscous gelled and crosslinked fluids may lose viscosity with time at high temperatures. To offset the loss of viscosity, the concentration of the gelling agent may be increased, which results in, inter alia, increased costs and increased friction pressure in the tubing through which the fluid is injected into a subterranean formation which makes pumping of the fracturing fluids more difficult. Thermal stabilizers such as sodium thiosulfate have been included in the fracturing fluids to scavenge oxygen and thereby increase the stabilities of the fracturing fluids at high temperatures. However, the use of thermal stabilizers may also increase the cost of the fracturing fluids.
Another problem which has been experienced in the use of gelled and crosslinked polysaccharide fracturing fluids involves the breaking of such fracturing fluids after fractures have been formed. Breakers such as oxidizers, enzymes and acid release agents that attack the polymer backbone have been used successfully.
In order to make the heretofore used gelled and crosslinked polysaccharide fracturing fluids carry sufficient proppant, the concentration of the crosslinking agent utilized has often had to be increased which in turn increases the cost and viscosity of the fracturing fluid. The water based fracturing fluids including gelled and crosslinked polysaccharide gelling agents have had significantly reduced fluid loss as compared to other fracturing fluids which reduces or eliminates the need for costly fluid loss additives. However, because the gelled and crosslinked polysaccharides have had high molecular weights, the filter cake produced from the viscous fracturing fluid on the walls of well bores penetrating producing formations and in fractures formed therein is often very difficult to remove.
Another problem experienced in the use of a water based fracturing fluid including a gelled and crosslinked polysaccharide gelling agent is that it often must be mixed in holding tanks for a considerable length of time for hydration of the gelling agent to occur. During the fracturing process carried out in a well, the hydrated fracturing fluid generally is pumped out of the holding tanks, mixed with proppant and other additives on the fly and pumped down the well bore to the formation being fractured. If during the job, the down hole pressure profile and other parameters that are obtained in real time indicate that a change in the fracturing fluid properties is required, that is, a change in the fracturing fluid viscosity to prevent a screen out of the fracture or the like, it is generally risky to do so since it takes a very long time for a change to be made and for the changed fracturing fluid to reach the formation being fractured. Another problem related to pumping the fracturing fluid from holding tanks and combining the proppant material, crosslinker and other additives used on the fly is that the procedure requires the use of expensive metering and other similar equipment.
Additionally, in many environmentally sensitive areas, the water based fracturing fluids containing polysaccharide gelling agents must be recovered from the well and disposed of by environmentally appropriate means which increases the overall cost of the fracturing treatment.
Certain types of subterranean formations, such as certain types of shales and coals have been observed to respond unfavorably to fracturing with conventional fracturing fluids. For example, in addition to opening a main, dominant fracture, the fracturing fluid may further invade numerous natural fractures (or “butts” and “cleats,” where the formation comprises coal) intersecting the main fracture, thereby permitting conventional gelling agents within the fracturing fluid to invade such intersecting natural fractures. When these openings re-close at the conclusion of fracturing, the conventional gelling agent may become trapped therein, which, inter alia, may inhibit the production of hydrocarbons from the natural fractures to the main fracture. Further, even in circumstances where the gelling agent does not become trapped within the natural fractures, a thin coating of the gel may nevertheless remain on the surface of the natural fractures after the conclusion of the fracturing operation. This may be problematic, inter alia, where the production of hydrocarbons from the subterranean formation involves processes such as desorption of the hydrocarbon from the surface of the formation, rather than production of hydrocarbons stored in interconnected pore spaces such as those found in conventional oil and gas reservoirs. Previous attempts to solve these problems have involved the use of less viscous fracturing fluids, such as non-gelled water. However, this is problematic, inter alia, because such fluids may prematurely dilate natural fractures perpendicular to the main fracture—a problem referred to as “near well bore fracture complexity,” or “near well bore tortuosity.” This is problematic because the creation of multiple fractures, as opposed to one or a few dominant fractures, results in reduced penetration into the formation, i.e., for a given injection rate, many short fractures are created rather than one or a few lengthy ones. This is problematic because in low permeability formations, the driving factor to increase productivity is the fracture length. Furthermore, the use of less viscous fracturing fluids has typically also required excessive fluid volumes and/or excessive injection pressure. The excessive entry pressure may frustrate attempts to place proppant into the fracture, causing the fracturing operation to fail in its attempt to increase hydrocarbon production.